As energy companies produce natural gas they also produce unwanted byproducts as part of the production process. Over the years environmental regulators have become vigilant in regulating the unwanted waste products from natural gas production. This vigilance over environmental regulation concerns has recently increased as energy companies have been producing natural gas using newer techniques (e.g., hydraulic fracking) and in fields that don't necessarily have sufficient gas treatment infrastructure (e.g., the Eagle Ford formation).
One type of natural gas byproduct that is often regulated is sulfur dioxide. Sulfur dioxide has been regulated for many years because, if emitted into the atmosphere, it mixes with moisture which can result in acid rain or other types of acid deposition that can be harmful to the environment. In natural gas production processes, sulfur dioxide results from the treatment of natural gas containing hydrogen sulfide. Hydrogen sulfide in natural gas is strictly regulated because it is a very dangerous gas. Hydrogen sulfide gas is also corrosive to gas pipelines and, under the high pressures typical of natural gas pipelines, can cause pipelines to fracture and leak. Hydrogen sulfide is, therefore, removed from the natural gas stream and is oxidized (through a flame source). This converts the hydrogen sulfide gas to mainly sulfur dioxide to reduce environmental and health risks associated with its disposal and to comply with state and federal environmental regulations. Nevertheless, the resulting sulfur dioxide can also be problematic and subject to restriction by regulations.
A conventional process to turn sour natural gas (i.e., “sour gas” is gas rich in hydrogen sulfide and other acid gases) into sweet natural gas (i.e., “sweet gas is gas lean in hydrogen sulfide and other acid gases) by removing substantially all of the hydrogen sulfide and other acid gases is the amine plant process. An amine process plant has an inlet stream of sour natural gas comprising hydrogen sulfide and perhaps other acid gases. The amine process plant takes the sour gas and turns it into sweet gas that can be sold and transported in natural gas pipelines or used in field gas applications. The inlet sour gas to the amine process plant can come from either one or a plurality of well heads. Amine process plants operate according to conventional processes, therefore, all details of the processes are not necessary to be detailed in this disclosure. Nevertheless, a background description of the process is here provided.
The amine process works by down-flowing a lean amine solution (e.g. an aqueous alkanolamine solution) through the inlet sour gas stream as it rises in an absorber column. Amine solutions are used frequently because they have a relatively high absorption capacity of acid gases, and they are easy to recycle because the acid gases can be stripped out of the rich amine solutions by heat, typically at pressures of 5-25 psig. During the counter-flow process, the hydrogen sulfide is stripped out of the sour gas stream by the lean amine solution to form a sweet gas stream leaving the top of the absorber. This sweet gas is suitable for insertion in a gas pipeline or used in field gas applications. The amine liquid stream after reaching the bottom of the column has hydrogen sulfide in solution (i.e., a “rich amine solution”) because the hydrogen sulfide remains in solution from strip out of the up-flowing inlet sour gas stream. Various amines are potentially usable in the process and they include, for example, monoethanolamine (MEA), methyldiethanolamine (MDEA), diethanolamine (DEA), diisopropanolamine (DIPA), triethanolamine (TEA), and DIGLYCOLAMINE® (DGA; (2-(2-aminoethoxy) ethanol) (a registered trademark of Huntsman Corporation), methylmonoethanolamine (MMEA), dimethylmonoethanolamine (DMMEA), aminomethylpropanol (AMP), and FLEXSORB® hindered amines (FLEXSORB® is a trademark of Exxon Corporation). These and other amines may be used alone or in combinations in aqueous mixtures. They may also be used as mixture of one or more of the amines with a physical solvent, such as, for example, piperazine, N-methyl-2-pyrrolidone (NMP), sulfolane (tetrahydrothiophenedioxide), SELEXOL® (DMEPEG; dimethylether of polyethylene glycol) (a trademark of Union Carbide Corporation), other dialkylethers of polyalkylene glycol, and methanol.
As part of the amine treatment process, the rich amine solution from stripping is regenerated as lean amine solution (i.e., low in hydrogen sulfide and other acid gases) using a distillation process to strip out the hydrogen sulfide and other acid gases from the rich amine solution. The lean amine solution is then reused in the absorber column to strip out yet more hydrogen sulfide of streamed sour gas. The amine regenerator unit is typically a thermal regeneration of the amine by counter-current flow of rich amine fed to the top of a stripping column and steam generated by reboiling the amine solution at the base of the stripping column, to reduce the acid gas content of the amine. This is then followed by cooling and return to the absorber of the lean amine solution. Accordingly, an amine solution is circulated around and around through the system. A typical amine process plant includes, for example, the absorber, the stripper (or regenerator), pumps, a reboiler, coolers, heat exchangers, and so forth. Amine process plants are commercially available from companies such as Spartan Energy Partners LLC (dba SEP Texas Energy Services LLC) of the Woodlands, Tex. The amine process is also described in some detail in U.S. Pat. No. 6,071,484 that is incorporated herein by reference.
The outlet gas recovered from the reboiler in the amine process plant is a sour tail gas that may contain a high level of hydrogen sulfide. It is, therefore, typically necessary to treat the sour flue gas so that minimal amounts of the hydrogen sulfide is released into the environment. This is done by incinerating the sour tail gas in a flare or thermal oxidizer. The thermal oxidizer raises the temperature of the sour tail gas to about 1400 to about 1600 degrees Fahrenheit and oxidizes most of the hydrogen sulfide to form sulfur dioxide. Thermal oxidizers are conventional and commercially available for purchase or lease as part of the amine plant itself. Thermal oxidizers are, therefore, commercially available from amine plant vendors such as Spartan Energy Partners LLC, or otherwise as stand-alone product from companies such as EnviroTherm International of Fort Worth, Tex.
Because of the previously discussed environmental restrictions on the release of sulfur dioxide into the atmosphere above certain levels, for some amine plants the flue gas leaving the thermal oxidizer has too high a level of sulfur dioxide for unrestricted release into the atmosphere. This is especially true for amine plants treating sour gas streams that have especially high levels of hydrogen sulfide. In such instances either the acid gas from the amine process plant or the flue gas from the thermal oxidizer must be treated or otherwise production must be limited.
Obviously, limiting production at a well head or well heads is not desired as the revenue from the well is adversely impacted. Conventional solutions such as using chemical scavengers may not be attractive because of the cost of the chemical scavenger. On the other hand, using a Claus unit (sulfur recovery) has a low variable cost but a very high up front capital cost.
It would, therefore, be a significant improvement in the art and technology to provide systems and methods for limiting the amount of sulfur dioxide that is emitted from an amine natural gas treatment facility in an environmentally responsible and cost efficient manner.